Compositions and methods for gas well treatment

ABSTRACT

A microemulsion system is disclosed which comprises a solvent subsystem, a co-solvent subsystem and a surfactant subsystem comprises at least one monoalkyl branched propoxy sulfate anionic surfactant, where the microemulsion system are useful in drilling, producing, remediation, and fracturing application to reduce water blocks and water blocking in formation of a producing formation.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to a new microemulsion system for rapidcleanup and enhanced production of hydrocarbon-containing fluids infractured tight subterranean formations and to methods for making andusing same.

More particularly, the present invention relates to a new microemulsionsystem for rapid clean up and enhanced production ofhydrocarbon-containing fluids in fractured tight subterraneanformations, where the microemulsion system includes a surfactantsubsystem including one monoalkyl branched propoxy sulfate or aplurality of monoalkyl branched propoxy sulfates, a solvent subsystemand a co-solvent subsystem and to methods for making and using same.

2. Description of the Related Art

Historically the use of microemulsion systems for water block cleaningpurposes and enhanced gas production purposes date back to at least1992.

For example, U.S. Pat. No. 5,310,002 disclosed formulations based onmicroemulsions, where the microemulsion includes (i) an alkyl alcoholhaving in the range of from 4 to 18 carbon atoms microemulsified intothe treatment fluid; (ii) a microemulsifying agent present in an amountsufficient to form and maintain a stable microemulsified dispersion ofthe alkyl alcohol in the treatment fluid; (iii) a microemulsion mutualsolvent selected from the group consisting of glycol ethers andalkyoxylates of glycol ethers; and (iv) a microemulsion co-solventselected from the group consisting of polyethylene glycol, primaryalcohols and alkyoxylates of alkyl alcohols.

U.S. Pat. No. 6,911,417 disclosed a formulation, and method for removingwater from a near-wellbore portion of a subterranean formationcontaining a crude oil and penetrated by a wellbore surfactant systems,where the formulation includes alkylpolyglycoside, ethoxylated alcoholsand linear alkyl alcohol or the formulation includes a hydrocarbonaceousliquid, alkylpolyglycoside, ethoxylated alcohol and linear alkylalcohol.

U.S. Published Pat. Appln. No. 20030166472 disclosed a microemulsionwell treatment microemulsion that is formed by combining asolvent-surfactant blend with a carrier fluid. In preferred embodiments,the solvent-surfactant blend includes a surfactant and a solventselected from the group consisting of terpenes and alkyl or aryl estersof short chain alcohols.

In many instances, when wellbores are drilled to penetrate asubterranean oil-bearing formation, it is found that upon completion ofthe wellbores, whether using an oil-based drilling mud, water-baseddrilling mud or water-based drill-in-fluids, the near-wellbore portionof the formation frequently retains quantities of water greater than thein-situ or natural water saturation levels of the formation. The in-situwater saturation levels are typically nearly, if not the same, as theconnate water saturation levels although in some formations the in-situwater saturation levels may be substantially greater or less than theconnate water saturation level for the formation.

As used herein, the term “connate water saturation” or “irreduciblewater saturation” refers to the minimum water saturation in asubterranean oil-bearing formation that can be achieved by flushing withoil, thereby increasing the oil saturation and the flowing fraction ofthe oil phase. This can be ascertained or determined in a formation corethat has been cleaned, dried and fully water saturated and thereafterflooded with oil. The water remaining after the oil flush is nearlyequal or equal to the connate water saturation level and cannot bereduced further by oil flushing or oil contact. The term “in-situ watersaturation” refers to the pre-existing formation water saturation levelprior to drilling or oil production.

Formations drilled for the production of crude oil arenaturally-occurring formations, which as well known to the art, underlieoverburden formations and may be above other oil-bearing ornon-oil-bearing formations beneath the formation of interest. When suchformations are drilled, it is known that they typically have at least anin-situ saturation, which is most commonly the connate (residualsaturation) water content. This water content is the inherent watersaturation level in the formation and may be increased by the invasionof water-based drilling fluid filtrate components. Typically, thepresence of water in excess of the in-situ water saturation level in theformation inhibits the production of crude oil from the formation.

In some formations, it has been noted that the formation has an in-situwater saturation level lower than the connate water saturation level,i.e., the formation actually imbibes water during drilling so that theformation as drilled may retain water up to or beyond the connate watersaturation level. In such formations, the imbibed water up to theconnate water saturation level is not typically removed by theproduction of crude oil. The water is only reduced back to the connatewater saturation level for the formation through natural mechanisms. Thepresence of water above the in-situ water saturation level can and doestypically inhibit the production of crude oil from the formation.

Previously, attempts to reduce water in the near-wellbore portion of theformation either back to the connate level or below have involved theuse of materials such as a mixture of methanol and water or the like, inattempts to remove the water with aqueous solutions that are at leastpartially soluble in the crude oil. The use of such approaches, whilethey may have had limited success in some instances, are generally lessthan completely successful and are less desirable because of the safetyconcerns on the use of highly flammable methanol solvent.

Various applications wherein alkylpolyglycosides in combination withethoxylated alcohols, alcohols and the like have been used in aqueousformations are shown in U.S. Pat. No. 4,985,154 issued Jan. 15, 1991 toBalzer, et al; U.S. Pat. No. 5,725,470 issued Mar. 10, 1998 toLazarowitz, et al; U.S. Pat. No. 5,830,831 issued Nov. 3, 1998 to Chan,et al; U.S. Pat. No. 5,874,386 issued Feb. 23, 1999 to Chan, et al; U.S.Pat. No. 5,977,032 issued Nov. 2, 1999 to Chan; U.S. Pat. No. 6,000,412issued Dec. 14, 1999 to Chan, et al; U.S. Pat. No. 6,090,754 issued Jul.18, 2000 to Chan, et al; and U.S. Pat. No. 6,112,814 issued Sep. 5, 2000to Chan, et al. These patents are hereby incorporated by reference.

In other instances, it has been found that water occasionally tends toaccumulate to levels above the connate water saturation level in thenear-wellbore area during production of oil from the well. As the wateraccumulates, it successively reduces the flowing fraction of the oilphase, and therefore the production of oil from the formation. Thiswater becomes trapped in the pore structure of the formation and remainsin place and does not move with the flow of crude oil from theformation.

Although numerous microemulsion systems have been produced for use inthe oil and gas industry, there is still a need the art for othermicroemulsion systems for use in the oil and gas industry or in relatedindustries.

DEFINITIONS OF THE INVENTION

The following definitions are provided in order to aid those skilled inthe art in understanding the detailed description of the presentinvention.

The term “surfactant” refers to a soluble, or partially soluble compoundthat reduces the surface tension of liquids, or reduces inter-facialtension between two liquids, or a liquid and a solid by congregating andorienting itself at these interfaces.

The term “amphoteric” refers to surfactants that have both positive andnegative charges. The net charge of the surfactant can be positive,negative, or neutral, depending on the pH of the solution.

The term “anionic” refers to those surfactants that possess a netnegative charge.

The term “cationic” refers to those surfactants that possess a netpositive charge.

The term “fracturing” refers to the process and methods of breaking downa geological formation, i.e. the rock formation around a well bore, bypumping fluid at very high pressures, in order to increase productionrates from a hydrocarbon reservoir. The fracturing methods of thisinvention use otherwise conventional techniques known in the art.

The term “proppant” refers to a granular substance suspended in thefracturing fluid during the fracturing operation, which serves to keepthe formation from closing back down upon itself once the pressure isreleased. Proppants envisioned by the present invention include, but arenot limited to, conventional proppants familiar to those skilled in theart such as sand, 20-40 mesh sand, resin-coated sand, sintered bauxite,glass beads, and similar materials.

The term “HLB value” means the hydrophil/lipophilic (hydro-phobe)balance. This value then is an indication of the oil or water solubilityof the product. The lower the HLB number the more oil soluble theproduct; and in turn the higher the HLB number the more water-solublethe product is. Below is a formula of how HLB values are calculated:

${\frac{{{Mol}.\mspace{14mu}{wt}.\mspace{14mu}{EO}} \times {moles}\mspace{14mu}{EO}}{{{Mol}.\mspace{14mu}{wt}.\mspace{14mu}{of}}\mspace{14mu}{Adduct}} \times 0.20} = {HLB}$

SUMMARY OF THE INVENTION

Well Treatment Formulations

The present invention provides a well treatment microemulsion systemincluding a solvent(s)-co-solvent(s)-surfactant blend.

The present invention provides a well treatment microemulsion systemincluding a surfactant subsystem, a solvent subsystem, and a co-solventsubsystem.

The present invention provides a well treatment microemulsion systemincluding a surfactant subsystem, a solvent subsystem, and a co-solventsubsystem, where the surfactant subsystem includes one monoalkylbranched propoxy sulfate or a plurality of monoalkyl branched propoxysulfates.

In certain embodiments, the present invention provides a microemulsionsystem including (a) a surfactant subsystem including at least onemonoalkyl branched propoxy sulfate anionic surfactant, (b) a solventsubsystem including an organic solvent and water, and (c) a co-solventsubsystem including a mixture of alcohols and at least one polypropyleneglycol. The surfactant subsystem can also include at least oneethoxylated alcohol and at least one ethylene oxide/propylene oxideblock copolymer having an HLB value between about 7 and about 15. Thesurfactant subsystem can further include at least one alkyl ethersulfate anionic surfactant. In certain embodiments, the mixture ofalcohols includes at least one short chain alcohol having between about1 and about 4 carbon atoms and at least one longer chain alcohol havingbetween about 6 and about 10 carbon atoms. In other embodiments, themixture of alcohols includes at least one short chain alcohol havingbetween about 2 and about 4 carbon atoms and at least one longer chainalcohol having between about 7 and about 9 carbon atoms. In otherembodiments, the mixture of alcohols includes isopropyl alcohol and1-octanol. In certain embodiments, the organic solvent includes benzene,an alkarene or a mixture thereof. Exemplary examples of alkarenesinclude toluene, xylenes, ethylbenzene, or mixtures of combinationsthereof. In other embodiments, the organic solvent includes a terpene ora mixture of terpenes. In other embodiments, the organic solvent isd-limonene or dipentene.

The present invention provides a well treatment microemulsion systemincluding a surfactant subsystem, a solvent subsystem, and a co-solventsubsystem. The surfactant subsystem includes (a) a monoalkyl branchedpropoxy sulfate or a plurality of monoalkyl branched propoxy sulfates,(b) at least one low foam generating ethoxylated alcohol, and (c) atleast one low foam generating block copolymer or plurality of blockcopolymers of ethylene oxide and propylene oxide having an HLB valuebetween about 7 and about 15. The surfactant subsystem can also includeother anionic surfactants such as sodium alkyl ether sulfates. Theco-solvent subsystem includes (a) at least one low molecular weightalcohol, (b) at least one higher molecular weight alcohol, and (c) atleast one polypropylene glycol. The solvent subsystem includes (a)terpene or a plurality of terpenes and (b) water.

The present invention provides a well treatment microemulsion systemincluding a surfactant subsystem, a solvent subsystem, and a co-solventsubsystem. The surfactant subsystem includes (a) between about 0.1weight percent and about 10 weight percent of monoalkyl branched propoxysulfate or a plurality of monoalkyl branched propoxy sulfates, (b)between about 0.1 weight percent and about 30 weight percent of a lowfoam generating ethoxylated alcohol comprising a narrow ranged reactionproduct of an alcohol having between about 8 and about 10 carbon atomsand an average of about 7 ethylene oxide groups per alcohol molecule and(c) between about 0.1 weight percent and about 30 weight percent of alow foam generating block copolymer or plurality of block copolymers ofethylene oxide and propylene oxide having a HLB value between about 7and 15. The co-solvent subsystem includes (a) between about 0.1 weightpercent and about 20 weight percent of isopropyl alcohol (IPA), (b)between about 0.1 weight percent and about 5 weight percent of1-octanol, and (c) between about 0.1 weight percent and about 15 weightpercent of a polypropylene glycol. The solvent subsystem includesbetween about 2 weight percent and about 25 weight percent of (a)terpene or a plurality of terpenes such as d-limonene or dipentene and(b) between about 20 weight percent and about 75 weight percent ofwater.

Methods for Using the Treating Methods

Well Treatments

The present invention provides a method for removing bound water fromgas and/or oil bearing subterranean formations, where the methodincludes the step of injecting into a formation an effective amount of awell treatment microemulsion system of this invention, the effectiveamount being sufficient to remove water blocks and to enhance formationproduction. The method also includes the step of maintaining the mixturein the formation for a time from about 2 to about 96 hours. The methodalso includes the step of producing fluids from the formation includingthe well treatment microemulsion system.

Fracturing

The present invention provides a method for fracturing a formationincluding the steps of pumping a fracturing fluid and then aproppant-containing fluid into a producing formation at a pressuresufficient to fracture the formation and to enhance productivity, wherethe fluid includes a microemulsion of this invention and where theproppant props open the formation after fracturing. The presentinvention also provides a method for fracturing a formation includingthe step of pumping a fracturing fluid including a proppant and amicroemulsion of this invention into a producing formation at a pressuresufficient to fracture the formation and to enhance productivity, wherethe proppant props open the formation after fracturing. The presentinvention also provides a method for fracturing a formation includingthe steps of pumping a fracturing fluid including a proppant into aproducing formation at a pressure sufficient to fracture the formationand to enhance productivity, where the proppant props open the formationafter fracturing and then pumping a well treatment of this inventioninto the fractured/propped formation for rapid clean up and enhancedproduction of hydrocarbon-containing fluids.

Producing

The present invention also provides a method for producing including thestep of circulating and/or pumping a fluid into a well on production,where the fluid includes a composition of this invention for rapid cleanup and enhanced production of hydrocarbon-containing fluids.

Drilling

The present invention also provides a method for drilling including thestep of circulating and/or pumping a fluid into a well during drillingoperations, where the fluid includes a composition of this invention forrapid clean up and enhanced flow hydrocarbon-containing fluids into thedrilling fluid to evidence the penetration into a producing formation.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention can be better understood with reference to the followingdetailed description together with the appended illustrative drawings inwhich like elements are numbered the same:

FIG. 1 depicts a plot of apparent permeability to nitrogen inmillidarcys versus cumulative fluid injected, before and after treatingwith 1 gal/Mgal of conventional microemulsion system in berea Sandstone@ 140 F. Permeability to air 8-10 millidarcys.

FIG. 2 depicts a plot of apparent permeability to nitrogen inmillidarcys versus cumulative fluid injected, before and after treatingwith 1 gal/Mgal of Sample 9 microemulsion system in berea Sandstone @140 F. Permeability to air 8-10 millidarcys.

FIG. 3 depicts a plot of apparent permeability to nitrogen inmillidarcys versus cumulative fluid injected, before and after treatingwith 1 gal/Mgal of Sample 13 microemulsion system in berea Sandstone @200 F. Permeability to air 8-10 millidarcys.

FIG. 4 depicts a plot of apparent permeability to nitrogen inmillidarcys versus cumulative fluid injected, before and after treatingwith 2 gal/Mgal of Sample 13 microemulsion system in berea Sandstone @200 F. Permeability to air 8-10 millidarcys.

FIG. 5 depicts a plot of apparent permeability to nitrogen inmillidarcys versus cumulative fluid injected, before and after treatingwith 1 gal/Mgal of Sample 4 microemulsion system in berea Sandstone @200 F. Permeability to air 8-10 millidarcys.

DETAILED DESCRIPTION OF THE INVENTION

The inventors have found that new thermodynamically stable,microemulsion systems including a surfactant subsystem, a solventsubsystem and water, where the systems are substantially opticallyisotropic and are capable of increasing gas and/or gas and oilproduction and water recovery. The inventors have found that the newmicroemulsion systems and uses thereof afford rapid clean up andenhanced production in fractured tight gas subterranean formations withlow foam generation. The inventors have found that by including onemonoalkyl branched propoxy sulfate or a plurality of monoalkyl branchedpropoxy sulfates in the surfactant subsystem of a microemulsion systemenhances the performance characteristics of the microemulsion system.

In certain embodiments, the new thermodynamically stable, microemulsionsystems include a nonionic surfactant or a plurality of nonionicsurfactants, an anionic surfactant or a plurality of anionicsurfactants, a co-solvent subsystem and a solvent system includingterpenes and water, where anionic surfactant or surfactants includes onemonoalkyl branched propoxy sulfate or a plurality of monoalkyl branchedpropoxy sulfates.

The microemulsion systems of this invention are adapted to be added tofracturing fluids for low permeability formations in concentrationsbetween about 1 gal/Mgal (gallons per thousand gallons) and about 5gal/Mgal. At this concentration range, the systems improves removal ofwater block (speeds up the removal of water blocks) thereby improvinggas production. Most of the commercially available microemulsion systemsfor this applications have been formulated with only non-ionicsurfactants having a cloud point for either the mother solution or thetreating solution of only 150° F. or lower. Another problem related tothe current systems is that they are extremely expensive.

Microemulsion Compositions

The present invention broadly relates to microemulsion formulations orcompositions including a surfactant subsystem, a solvent subsystem andco-solvent subsystem, where the surfactant subsystem includes onemonoalkyl branched propoxy sulfate or a plurality of monoalkyl branchedpropoxy sulfates.

In certain embodiments, the present invention relates to a microemulsionsystem including (a) a surfactant subsystem including at least onemonoalkyl branched propoxy sulfate anionic surfactant, (b) a solventsubsystem including an organic solvent and water, and (c) a co-solventsubsystem including a mixture of alcohols and at least one polypropyleneglycol. The surfactant subsystem can also include at least oneethoxylated alcohol and at least one ethylene oxide/propylene oxideblock copolymer having an HLB value between about 7 and about 15. Thesurfactant subsystem can further include at least one alkyl ethersulfate anionic surfactant. In certain embodiments, the mixture ofalcohols includes at least one short chain alcohol having between about1 and about 4 carbon atoms and at least one longer chain alcohol havingbetween about 6 and about 10 carbon atoms. In other embodiments, themixture of alcohols includes at least one short chain alcohol havingbetween about 2 and about 4 carbon atoms and at least one longer chainalcohol having between about 7 and about 9 carbon atoms. In otherembodiments, the mixture of alcohols includes isopropyl alcohol and1-octanol. In certain embodiments, the organic solvent includes benzene,an alkarene or a mixture thereof. Exemplary examples of alkarenesinclude toluene, xylenes, ethylbenzene, or mixtures of combinationsthereof. In other embodiments, the organic solvent includes a terpene ora mixture of terpenes. In other embodiments, the organic solvent isd-limonene or dipentene.

In certain embodiments of the microemulsion system of this invention,the solvent subsystem includes:

from about 5 wt. % to about 75% wt. % water, and

from about 0.1 wt % to about 50 wt % of a terpene or plurality ofterpenes.

In certain embodiments of the microemulsion system of this invention,the solvent subsystem includes:

from about 20 wt. % to about 75% wt. % water, and

from about 2 wt % to about 25 wt % of a terpene or a mixture ofterpenes.

In certain embodiments of the microemulsion system of this invention,the surfactant subsystem includes:

from 0.1 wt % to about 30% wt % of at least one ethoxylated alcoholobtained of a narrow range catalyst technology containing from about 8to about 10 carbon chain length alkyls with an average of about 7ethylene oxide groups per mole

from 0.1 wt % to about 30 wt % at least one block copolymer of ethyleneoxide and propylene oxide having a HLB value between about 7 and about15,

from 0.1 wt. % to about 10 wt. % of at least one monoalkyl branchedpropoxy sulfate, and

from 0.1 wt % to about 10 wt % of sodium tridecyl ether sulfate.

In certain embodiments of the microemulsion system of this invention,the co-solvent system includes:

from about 0.1 wt. % to about 20 wt. % at least one short chain linearalcohol,

from about 0.1 wt. % to about 15 wt. % at least one longer chain linearalcohol, and

from about 0.1 wt. % to about 15 wt. % at least one polypropyleneglycol.

In certain embodiments of the microemulsion system of this invention,the co-solvent system includes:

from about 0.1 wt. % to about 15 wt. % at least one short chain linearalcohol,

from about 0.5 wt. % to about 15 wt. % at least one longer chain linearalcohol, and

from about 0.5 wt. % to about 15 wt. % at least one polypropyleneglycol.

In certain embodiments, the microemulsion system of this inventionincludes:

a surfactant subsystem including:

-   -   from about 0.5 wt. % to about 30 wt. % at least one ethoxylated        alcohol comprising a reaction product of a C₁₂-C₁₆ alcohol and        six (6) to eight (8) ethylene oxide (EO) units,    -   from about 0.5 wt. % to about 30 wt. % at least one ethylene        oxide (EO)/propylene oxide (PO) copolymer having a HLB value        between about 7 and about 15,    -   from about 0.1 wt. % to about 10 wt. % at least one monoalkyl        branched propoxy sulfate,

a co-solvent system including:

-   -   from about 0.1 wt. % to about 15 wt. % at least one short chain        linear alcohol,    -   from about 0.5 wt. % to about 10 wt. % at least one longer chain        linear alcohol,    -   from about 0.5 wt. % to about 15 wt. % at least one short        polypropylene glycol, and

a solvent system including:

-   -   from about 1 wt. % to about 50 wt. % of at least one terpene,        and    -   from about 20 wt. % to about 75 wt. % of water.

In other embodiments, the microemulsion system of this inventionincludes:

a surfactant subsystem including:

-   -   from about 1 wt. % to about 30 wt. % at least one ethoxylated        alcohol comprising a reaction product of a C₁₂-C₁₆ alcohol and        six (6) to eight (8) ethylene oxide (EO) units,    -   from about 1 wt. % to about 30 wt. % at least one ethylene oxide        (EO)/propylene oxide (PO) copolymer having a HLB value between        about 7 and about 15,    -   from about 1 wt. % to about 10 wt. % at least one monoalkyl        branched propoxy sulfate,

a co-solvent system including:

-   -   from about 1 wt. % to about 15 wt. % at least one short chain        linear alcohol,    -   from about 1 wt. % to about 10 wt. % at least one longer chain        linear alcohol,    -   from about 1 wt. % to about 15 wt. % at least one polypropylene        glycol,

a solvent system including:

-   -   from about 1 wt. % to about 25 wt. % of a first terpene,    -   from about 1 wt. % to about 25 wt. % of a second terpene, and    -   from about 20 wt. % to about 75 wt. % water.

In other embodiments, the microemulsion system of this inventionincludes:

a surfactant subsystem including:

-   -   from about 2 wt. % to about 30 wt. % at least one ethoxylated        alcohol comprising a reaction product of a C₁₂-C₁₆ alcohol and        six (6) to eight (8) ethylene oxide (EO) units,    -   from about 2 wt. % to about 30 wt. % at least one ethylene oxide        (EO)/propylene oxide (PO) copolymer having a HLB value between        about 7 and about 15,    -   from about 2 wt. % to about 10 wt. % at least one C₁₅-C₁₇        monoalkyl branched propoxy sulfate,

a solvent system including:

-   -   from about 0.1 wt. % to about 15 wt. % of isopropyl alcohol        (IPA),    -   from about 0.5 wt. % to about 10 wt. % of 1-octanol,    -   from about 0.5 wt. % to about 15 wt. % at least one        polypropylene glycol, and

a co-solvent system including:

-   -   from about 0.1 wt. % to about 25 wt. % of d-limonene,    -   from about 0.1 wt. % to about 25 wt. % of dipentene, and    -   from about 20 wt. % to about 75 wt. % water.

In the discussion of the present invention, reference is made to boundwater to refer to imbibed water, water above the connate saturationlevel, water accumulated and retained in the near-wellbore region aroundthe well, and the like.

All the formulations of this invention are designed to have low foamgeneration when added to the treating fluids.

The compositions of this invention including a microemulsion forremoving water positioned in a formation, producing a very low surfacetension microemulsion system. The low surface tension with the excesswater phase allows the trapped water to be mobilized and displaced outof the formation.

The mixture is injected into a subterranean formation by simplyinjecting it into a well or wellbore in the zone of interest of theformation and thereafter pressurizing it into the formation for theselected distance. Methods for achieving the placement of a selectedquantity of a mixture in a subterranean formation are well known, aswill be discussed hereinafter.

After treatment of the formation for a selected period of time, which istypically from about 2 to about 96 hours, and preferably from about 16to about 24 hours, the mixture is removed from the near-wellbore portionof the subterranean formation. This removal may conveniently beaccomplished by simply producing the well. The compositions of thisinvention are recovered from the near-wellbore portion of the formationand produced along with crude oil.

It has been found that the use of this composition has been effective toremove water from the near-wellbore portions of subterranean formationsdown to, and in some instances below, the connate water saturation levelof the formation. As a result increased gas and oil production has beenachieved.

Method for Treating

The present invention also relates to a method for removing bound waterfrom oil and/or gas bearing subterranean formations. The method includesthe step of injecting into a formation an effective amount of amicroemulsion system. The system comprises a surfactant subsystemincluding at least one monoalkyl branched propoxy sulfate anionicsurfactant, a solvent subsystem including an organic solvent and water,and a co-solvent subsystem including a mixture of alcohols and at leastone polypropylene glycol. The effective amount being sufficient toremove water blocks and to enhance formation production. The method canalso include the step of maintaining the system in the formation for atime from about 8 to about 96 hours. The method can also include thestep of producing fluids from the formation including the microemulsionsystem. The effective amount also being sufficient to treat accessibleportions of the formation and to treat portions extending radiallyoutwardly from the accessible portions to a distance of about 6 inchesto about 3 feet. The method can also include the step of maintaining themixture in the accessible portions for a time from about 8 to about 96hours.

Method for Fracturing and/or Propping

The present invention broadly relates to methods for fracturing aformation including the step of pumping a fracturing fluid including acomposition of this invention into a producing formation at a pressuresufficient to fracture the formation.

The present invention also relates to a method for fracturing aformation comprising the step of pumping, into a producing formation ata pressure sufficient to fracture the formation and to enhanceproductivity. The fracturing fluid comprises a proppant and amicroemulsion system including a surfactant subsystem including at leastone monoalkyl branched propoxy sulfate anionic surfactant, a solventsubsystem including an organic solvent and water, and a co-solventsubsystem including a mixture of alcohols and at least one polypropyleneglycol. The proppant props is adapted to open the formation afterfracturing, and the microemulsion system is adapted to reduce waterblocks and water blocking in the formation.

The present invention also relates to a method for fracturing aformation including the step of pumping a fracturing fluid includinginto a producing formation at a pressure sufficient to fracture theformation and to enhance productivity. The method can also include thestep of pumping in a proppant fluid including a proppant and a microemulsion system comprising a surfactant sub system including at leastone monoalkyl branched propoxy sulfate anionic surfactant, a solventsubsystem including an organic solvent and water, and a co-solventsubsystem including a mixture of alcohols and at least one polypropyleneglycol. The proppant props open the formation after fracturing, and themicroemulsion system reduces water blocks and water blocking in theformation.

The present invention also relates to a method for fracturing aformation including the step of pumping a fracturing fluid into aproducing formation at a pressure sufficient to fracture the formationand to enhance productivity. The method also includes the step ofpumping in a proppant fluid including a proppant, where the proppantprops open the formation after fracturing. The method also includes thestep pumping a microemulsion system comprising a surfactant subsystemincluding at least one monoalkyl branched propoxy sulfate anionicsurfactant, a solvent subsystem including an organic solvent and water,and a co-solvent subsystem including a mixture of alcohols and at leastone polypropylene glycol, where microemulsion system reduces waterblocks and water blocking in the formation.

Method for Producing

The present invention also broadly relates to a method for producingincluding the step of circulating and/or pumping a fluid into aformation, where the fluid includes a composition of this invention andthe composition of this invention is designed to reduce, remove orprevent water block formation during production.

The present invention also relates to a method for producing comprisingcirculating and/or pumping into a well on production a fluid including amicroemulsion system comprising a surfactant subsystem including atleast one monoalkyl branched propoxy sulfate anionic surfactant, asolvent subsystem including an organic solvent and water, and aco-solvent subsystem including a mixture of alcohols and at least onepolypropylene glycol. The microemulsion system reduces water blocks andwater blocking in the formation.

Methods for Drilling

The present invention also broadly relates to a method for drillingincluding the step of circulating and/or pumping a fluid into a wellduring drilling operations, where the fluid includes a composition ofthis invention for rapid clean up, reduced water block formation andenhanced flow hydrocarbon-containing fluids into the drilling fluid toevidence the penetration into a producing formation.

The present invention also relates to a method for drilling comprisingthe step of circulating and/or pumping into a well during drilling afluid including a microemulsion system comprising a surfactant subsystemincluding at least one monoalkyl branched propoxy sulfate anionicsurfactant, a solvent subsystem including an organic solvent and water,and a co-solvent subsystem including a mixture of alcohols and at leastone polypropylene glycol. The microemulsion system reduces fines anddebris in the borehole during drilling.

Suitable Reagents

Suitable ethoxylated alcohols include, without limitation, ethoxylatedalcohols prepared from an alcohol having between about eight (8) andabout ten (10) carbon atoms and between about six (5) and about eight(8) ethylene oxide (EO) residues, or mixtures thereof. In certainembodiments, the ethoxylated alcohols comprise a narrow ranged reactionproduct of an alcohol having between about 8 and about 10 carbon atomsand an average of about 7 ethylene oxide groups per alcohol molecule ormixtures thereof.

Suitable short chained alcohols include, without limitation, short chainalcohols having between about one (1) and about six (6) carbon atoms, ormixtures thereof. Exemplary examples include, without limitation,methanol, ethanol, propanol, isopropanol (isopropyl alcohol), n-butanol,iso-butanol, n-pentanol, n-hexanol, cyclohexanol, iso-hexanol,t-butanol, butanol, 2-ethyl-hexanol or other short chained alcoholshaving one to six carbon atoms, where one or more of the hydrogen atomscan be a halogen atom, or mixtures thereof. The short chained alcoholsof the solvent-surfactant blend are thought to stabilize themicroemulsion. In addition, the short chained alcohol lower the freezingpoint of the well treatment microemulsion. In certain embodiment, theshort chained alcohol is isopropanol or isopropyl alcohol (IPA).

Suitable long chain alcohols include, without limitation, alcoholshaving between about eight (8) and about twelve (12) carbon atoms.Exemplary examples include 1-octanol, 1-nonanol, 1-decanol, 1-undecanol,1-dodecanol, or mixtures thereof, where one or more of the hydrogenatoms can be a halogen atom, or mixtures thereof. In addition, the longchained alcohol can help into the defomer properties when added themicroemulsion to a water base system. In certain embodiment, the longerchained alcohol is 1-octanol.

Suitable terpenes include, without limitations, d-limonene, l-limonene,d,l-limonene, γ-terpinene, α-phellandrene, p-cymene, α-pinene, ormixtures thereof.

New Microemulsion Systems

The new microemulsion containing systems of this invention aredifferentiated from prior art microemulsion systems via the inclusion inthe surfactant subsystem a C₁₁-C₁₇ monobranched propoxy alkyl sulfate ormixtures thereof. These anionic propoxylated surfactants allow anincrease of a cloud point of the treating solutions of this invention toa temperature of about 170° F. and decrease of a freezing pointtemperature to about 5° F.

The microemulsions of this invention can also include other freezeprevention additives such as ethylene glycols (EG), polyethylene glycols(PEG), propylene glycols (PG) and triethylene glycols (TEG).

The microemulsion compositions of this invention can optionally includea salt. The addition of a salt to the microemulsion compositions reducesthe amount of water needed as a carrier fluid and also lowers thefreezing point of the well treatment microemulsion. Among the salts thatmay be added for stability and co-solvent substitution, NaCl, KCl,CaCl₂, and MgCl₂ are presently preferred. Others suitable salts can beformed from K, Na, Br, Cr, Cs and Bi families.

After blending the solvent subsystem, surfactant subsystem andco-solvent subsystem to form the microemulsion composition of thisinvention, it may be desirable to form a diluted microemulsioncomposition by adding a diluent before addition to the carrier fluid. Incertain embodiments, the diluents include water and water and ethyleneglycol, polyethylene glycol, propylene glycol, polypropylene glycol,triethylene glycol (TEG) mixtures. In other embodiments, the diluentsare 90% by volume water and 10% by volume triethylene glycol. It will beunderstood that upon addition of the diluent, the solvent surfactantblend may partially or completely emulsify.

Although the microemulsion compositions of this invention are adaptedespecially for use in well remediation operations, well stimulationoperations, well fracturing operations, water de-blocking, welloperations, well acidizing operations, well drilling operations, wellproduction operations, and hydrogen sulfide mitigation applications, itwill be understood that the inventive microemulsion compositions of thisinvention can find use in other applications where microemulsions haveapplicability. For example, the microemulsion composition of thisinvention may find application as a composition for cleaning surfaceequipment and downhole equipment.

During drilling operations, the microemulsion compositions of thisinvention can be added to drilling fluids and injected into the wellborethrough the drill string. The microemulsion compositions are generallyeffective at removing fines and debris from the wellbore created by thedrilling process. The microemulsion compositions of this invention canbe tailored to operate in oil or water based drilling fluids. Thetailoring includes the ratio of the organic solvent to water in thesolvent subsystem of the microemulsion compositions of this invention.By changing the relative organic to water ratio, the microemulsion canbe tailored to have a water continuous phase or an organic continuousphase or can be tailored to have initially one continuous phase thatwill change as the microemulsion encounters a water rich fluid or anorganic rich fluid. Moreover, the microemulsion compositions of thisinvention can be tailored so that the microemulsion rapidly switchesfrom a water-in-oil to an oil-in-water microemulsion.

The well treatment microemulsions can also be used to deliver acidsduring acidizing operations. Acids commonly used include hydrochloric,acetic, formic, and hydrochloric-hydroflouric acids. In certainembodiments, the selected microemulsion compositions of this invention(dilute or concentrate) is combined with an acidified carrier fluid toprepare a microemulsion suitable for acidizing operations. In certainembodiments, the acidizing fluid includes about 0.2%-5% by volume of themicroemulsion compositions of this invention and about 3%-28% by volumeof acid. In other embodiments, the acidizing fluid includes about0.2%-5% of the microemulsion compositions of this invention and about15% by volume of hydrochloric acid. The concentration of themicroemulsion compositions of this invention in gelled fluids lowers thefriction created by contact with conduits, thereby facilitating theinjection and withdrawal of the well treatment microemulsion.

Fracturing Fluids

Generally, a hydraulic fracturing treatment involves pumping aproppant-free viscous fluid, or pad, usually water with some fluidadditives to generate high viscosity, into a well faster than the fluidcan escape into the formation so that the pressure rises and the rockbreaks, creating artificial fracture and/or enlarging existing fracture.After fracturing the formation, a propping agent, generally a solidmaterial such as sand is added to the fluid to form a slurry that ispumped into the newly formed fractures in the formation to prevent themfrom closing when the pumping pressure is released. The proppanttransport ability of a base fluid depends on the type of viscosifyingadditives added to the water base.

Water-base fracturing fluids with water-soluble polymers added to make aviscosified solution are widely used in the art of fracturing. Since thelate 1950s, more than half of the fracturing treatments are conductedwith fluids comprising guar gums, high-molecular weight polysaccharidescomposed of mannose and galactose sugars, or guar derivatives such ashydropropyl guar (HPG), carboxymethyl guar (CMG).carboxymethylhydropropyl guar (CMHPG). Crosslinking agents based onboron, titanium, zirconium or aluminum complexes are typically used toincrease the effective molecular weight of the polymer and make thembetter suited for use in high-temperature wells.

To a lesser extent, cellulose derivatives such as hydroxyethylcellulose(HEC) or hydroxypropylcellulose (HPC) andcarboxymethylhydroxyethylcellulose (CMHEC) are also used, with orwithout crosslinkers. Xanthan and scleroglucan, two biopolymers, havebeen shown to have excellent proppant-suspension ability even thoughthey are more expensive than guar derivatives and therefore used lessfrequently. Polyacrylamide and polyacrylate polymers and copolymers areused typically for high-temperature applications or friction reducers atlow concentrations for all temperatures ranges.

Polymer-free, water-base fracturing fluids can be obtained usingviscoelastic surfactants. These fluids are normally prepared by mixingin appropriate amounts of suitable surfactants such as anionic,cationic, nonionic and zwitterionic surfactants. The viscosity ofviscoelastic surfactant fluids is attributed to the three dimensionalstructure formed by the components in the fluids. When the concentrationof surfactants in a viscoelastic fluid significantly exceeds a criticalconcentration, and in most cases in the presence of an electrolyte,surfactant molecules aggregate into species such as micelles, which caninteract to form a network exhibiting viscous and elastic behavior.

Cationic viscoelastic surfactants—typically consisting of long-chainquaternary ammonium salts such as cetyltrimethylammonium bromide(CTAB)—have been so far of primarily commercial interest in wellborefluid. Common reagents that generate viscoelasticity in the surfactantsolutions are salts such as ammonium chloride, potassium chloride,sodium chloride, sodium salicylate and sodium isocyanate and non-ionicorganic molecules such as chloroform. The electrolyte content ofsurfactant solutions is also an important control on their viscoelasticbehavior. Reference is made for example to U.S. Pat. No. 4,695,389, U.S.Pat. No. 4,725,372, U.S. Pat. No. 5,551,516, U.S. Pat. No. 5,964,295,and U.S. Pat. No. 5,979,557. However, fluids comprising this type ofcationic viscoelastic surfactants usually tend to lose viscosity at highbrine concentration (10 pounds per gallon or more). Therefore, thesefluids have seen limited use as gravel-packing fluids or drillingfluids, or in other applications requiring heavy fluids to balance wellpressure. Anionic viscoelastic surfactants are also used.

It is also known from International Patent Publication WO 98/56497, toimpart viscoelastic properties using amphoteric/zwitterionic surfactantsand an organic acid, salt and/or inorganic salt. The surfactants are forinstance dihydroxyl alkyl glycinate, alkyl ampho acetate or propionate,alkyl betaine, alkyl amidopropyl betaine and alkylamino mono- ordi-propionates derived from certain waxes, fats and oils. Thesurfactants are used in conjunction with an inorganic water-soluble saltor organic additives such as phthalic acid, salicylic acid or theirsalts. Amphoteric/zwitterionic surfactants, in particular thosecomprising a betaine moiety are useful at temperature up to about 150°C. and are therefore of particular interest for medium to hightemperature wells. However, like the cationic viscoelastic surfactantsmentioned above, they are usually not compatible with high brineconcentration.

The proppant type can be sand, intermediate strength ceramic proppants(available from Carbo Ceramics, Norton Proppants, etc.), sinteredbauxites and other materials known to the industry. Any of these basepropping agents can further be coated with a resin (available fromSantrol, a Division of Fairmount Industries, Borden Chemical, etc.) topotentially improve the clustering ability of the proppant. In addition,the proppant can be coated with resin or a proppant flowback controlagent such as fibers for instance can be simultaneously pumped. Byselecting proppants having a contrast in one of such properties such asdensity, size and concentrations, different settling rates will beachieved.

“Waterfrac treatments employ the use of low cost, low viscosity fluidsin order to stimulate very low permeability reservoirs. The results havebeen reported to be successful (measured productivity and economics) andrely on the mechanisms of asperity creation (rock spalling), sheardisplacement of rock and localized high concentration of proppant tocreate adequate conductivity. It is the last of the three mechanismsthat is mostly responsible for the conductivity obtained in “waterfrac”treatments. The mechanism can be described as analogous to a wedgesplitting wood.

An aqueous fracturing fluid may be prepared by blending a hydratablepolymer with an aqueous base fluid. The base aqueous fluid can be, forexample, water or brine. Any suitable mixing apparatus may be used forthis procedure. In the case of batch mixing, the hydratable polymer andaqueous fluid are blended for a period of time which is sufficient toform a hydrated sol.

Hydraulic fracturing techniques are widely employed to enhance oil andgas production from subterranean formations. During hydraulicfracturing, fluid is injected into a well bore under high pressure. Oncethe natural reservoir pressures are exceeded, the fracturing fluidinitiates a fracture in the formation which generally continues to growduring pumping. As the fracture widens to a suitable width during thecourse of the treatment, a propping agent is then also added to thefluid. The treatment design generally requires the fluid to reach amaximum viscosity as it enters the fracture which affects the fracturelength and width. The viscosity of most fracturing fluids is generatedfrom water-soluble polysaccharides, such as galactomannans or cellulosederivatives. Employing crosslinking agents, such as borate, titanate, orzirconium ions, can further increase the viscosity. The gelled fluid maybe accompanied by a propping agent (i.e., proppant) which results inplacement of the proppant within the fracture thus produced. Theproppant remains in the produced fracture to prevent the completeclosure of the fracture and to form a conductive channel extending fromthe well bore into the formation being treated once the fracturing fluidis recovered.

In order for the treatment to be successful, it is preferred that thefluid viscosity eventually diminish to levels approaching that of waterafter the proppant is placed. This allows a portion of the treatingfluid to be recovered without producing excessive amounts of proppantafter the well is opened and returned to production. The recovery of thefracturing fluid is accomplished by reducing the viscosity of the fluidto a lower value such that it flows naturally from the formation underthe influence of formation fluids. This viscosity reduction orconversion is referred to as “breaking” and can be accomplished byincorporating chemical agents, referred to as “breakers,” into theinitial gel.

Certain gels of fracturing fluids, such as those based upon guarpolymers, undergo a natural break without the intervention of a breakingagent. However, the breaking time for such gelled fluids generally isexcessive and impractical, being somewhere in the range from greaterthan 24 hours to in excess of weeks, months, or years depending onreservoir conditions. Accordingly, to decrease the break time of gelsused in fracturing, chemical agents are usually incorporated into thegel and become a part of the gel itself. Typically, these agents areeither oxidants or enzymes which operate to degrade the polymeric gelstructure. Most degradation or “breaking” is caused by oxidizing agents,such as persulfate salts (used either as is or encapsulated), chromoussalts, organic peroxides or alkaline earth or zinc peroxide salts, or byenzymes.

In addition to the importance of providing a breaking mechanism for thegelled fluid to facilitate recovery of the fluid and to resumeproduction, the timing of the break is also of great importance. Gelswhich break prematurely can cause suspended proppant material to settleout of the gel before being introduced a sufficient distance into theproduced fracture. Premature breaking can also lead to a prematurereduction in the fluid viscosity, resulting in a less than desirablefracture width in the formation causing excessive injection pressuresand premature termination of the treatment.

On the other hand, gelled fluids which break too slowly can cause slowrecovery of the fracturing fluid from the produced fracture withattendant delay in resuming the production of formation fluids andseverely impair anticipated hydrocarbon production. Additional problemsmay occur, such as the tendency of proppant to become dislodged from thefracture, resulting in at least partial closing and decreased efficiencyof the fracturing operation. Preferably, the fracturing gel should beginto break when the pumping operations are concluded. For practicalpurposes, the gel preferably should be completely broken within about 24hours after completion of the fracturing treatment. Gels useful in thisregard include those disclosed in U.S. Pat. Nos. 3,960,736; 5,224,546;6,756,345; and 6,793,018, incorporated herein by reference.

Suitable solvents fore use in this invention include, withoutlimitation, water. The solvent may be an aqueous potassium chloridesolution.

Suitable inorganic breaking agent include, without limitation, ametal-based oxidizing agent, such as an alkaline earth metal or atransition metal; magnesium peroxide, calcium peroxide, or zincperoxide.

Suitable ester compound include, without limitation, an ester of apolycarboxylic acid, e.g., an ester of oxalate, citrate, or ethylenediamine tetraacetate. Ester compound having hydroxyl groups can also beacetylated, e.g., acetylated citric acid to form acetyl triethylcitrate.

Suitable hydratable polymers that may be used in embodiments of theinvention include any of the hydratable polysaccharides which arecapable of forming a gel in the presence of a crosslinking agent. Forinstance, suitable hydratable polysaccharides include, but are notlimited to, galactomannan gums, glucomannan gums, guars, derived guars,and cellulose derivatives. Specific examples are guar gum, guar gumderivatives, locust bean gum, Karaya gum, carboxymethyl cellulose,carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose.Presently preferred gelling agents include, but are not limited to, guargums, hydroxypropyl guar, carboxymethyl hydroxypropyl guar,carboxymethyl guar, and carboxymethyl hydroxyethyl cellulose. Suitablehydratable polymers may also include synthetic polymers, such aspolyvinyl alcohol, polyacrylamides, poly-2-amino-2-methyl propanesulfonic acid, and various other synthetic polymers and copolymers.Other suitable polymers are known to those skilled in the art.

The hydratable polymer may be present in the fluid in concentrationsranging from about 0.10% to about 5.0% by weight of the aqueous fluid.In certain embodiment, a range for the hydratable polymer is about 0.20%to about 0.80% by weight.

A suitable crosslinking agent can be any compound that increases theviscosity of the fluid by chemical crosslinking, physical crosslinking,or any other mechanisms. For example, the gellation of a hydratablepolymer can be achieved by crosslinking the polymer with metal ionsincluding boron, zirconium, and titanium containing compounds, ormixtures thereof. One class of suitable crosslinking agents isorganotitanates. Another class of suitable crosslinking agents isborates as described, for example, in U.S. Pat. No. 4,514,309. Theselection of an appropriate crosslinking agent depends upon the type oftreatment to be performed and the hydratable polymer to be used. Theamount of the crosslinking agent used also depends upon the wellconditions and the type of treatment to be effected, but is generally inthe range of from about 10 ppm to about 1000 ppm of metal ion of thecrosslinking agent in the hydratable polymer fluid. In someapplications, the aqueous polymer solution is crosslinked immediatelyupon addition of the crosslinking agent to form a highly viscous gel. Inother applications, the reaction of the crosslinking agent can beretarded so that viscous gel formation does not occur until the desiredtime.

The organotitanate constituent can be TYZOR® titanium chelate estersfrom E.I du Pont de Nemours & Company. The organotitanate constituentcan be a mixture of a first organotitanate compound having a lactatebase and a second organotitanate compound having triethanolamine base.

The boron constituent can be selected from the group consisting of boricacid, sodium tetraborate, and mixtures thereof. These are described inU.S. Pat. No. 4,514,309.), borate based ores such as ulexite andcolemanite, Ti(IV) acetylacetonate, Ti(IV) triethanolamine, Zr lactate,Zr triethanolamine, Zr lactate-triethanolamine, or Zrlactate-triethanolamine-triisopropanolamine. In some embodiments, thewell treatment fluid composition may further comprise a proppant.

“Premature breaking” as used herein refers to a phenomenon in which agel viscosity becomes diminished to an undesirable extent before all ofthe fluid is introduced into the formation to be fractured. Thus, to besatisfactory, the gel viscosity should preferably remain in the rangefrom about 50% to about 75% of the initial viscosity of the gel for atleast two hours of exposure to the expected operating temperature.Preferably the fluid should have a viscosity in excess of 100 centipoise(cP) at 100 sec⁻¹ while injection into the reservoir as measured on aFann 50 C viscometer in the laboratory.

“Complete breaking” as used herein refers to a phenomenon in which theviscosity of a gel is reduced to such a level that the gel can beflushed from the formation by the flowing formation fluids or that itcan be recovered by a swabbing operation. In laboratory settings, acompletely broken, non-crosslinked gel is one whose viscosity is about10 cP or less as measured on a Model 35 Fann viscometer having a R1B1rotor and bob assembly rotating at 300 rpm.

The pH of an aqueous fluid which contains a hydratable polymer can beadjusted if necessary to render the fluid compatible with a crosslinkingagent. Preferably, a pH adjusting material is added to the aqueous fluidafter the addition of the polymer to the aqueous fluid. Typicalmaterials for adjusting the pH are commonly used acids, acid buffers,and mixtures of acids and bases. For example, sodium bicarbonate,potassium carbonate, sodium hydroxide, potassium hydroxide, and sodiumcarbonate are typical pH adjusting agents. Acceptable pH values for thefluid may range from neutral to basic, i.e., from about 5 to about 14.Preferably, the pH is kept neutral or basic, i.e., from about 7 to about14, more preferably between about 8 to about 12.

The term “breaking agent” or “breaker” refers to any chemical that iscapable of reducing the viscosity of a gelled fluid. As described above,after a fracturing fluid is formed and pumped into a subterraneanformation, it is generally desirable to convert the highly viscous gelto a lower viscosity fluid. This allows the fluid to be easily andeffectively removed from the formation and to allow desired material,such as oil or gas, to flow into the well bore. This reduction inviscosity of the treating fluid is commonly referred to as “breaking”.Consequently, the chemicals used to break the viscosity of the fluid isreferred to as a breaking agent or a breaker.

There are various methods available for breaking a fracturing fluid or atreating fluid. Typically, fluids break after the passage of time and/orprolonged exposure to high temperatures. However, it is desirable to beable to predict and control the breaking within relatively narrowlimits. Mild oxidizing agents are useful as breakers when a fluid isused in a relatively high temperature formation, although formationtemperatures of 300° F. (149° C.) or higher will generally break thefluid relatively quickly without the aid of an oxidizing agent.

Examples of inorganic breaking agents for use in this invention include,but are not limited to, persulfates, percarbonates, perborates,peroxides, perphosphates, permanganates, etc. Specific examples ofinorganic breaking agents include, but are not limited to, alkalineearth metal persulfates, alkaline earth metal percarbonates, alkalineearth metal perborates, alkaline earth metal peroxides, alkaline earthmetal perphosphates, zinc salts of peroxide, perphosphate, perborate,and percarbonate, and so on. Additional suitable breaking agents aredisclosed in U.S. Pat. Nos. 5,877,127; 5,649,596; 5,669,447; 5,624,886;5,106,518; 6,162,766; and 5,807,812. In some embodiments, an inorganicbreaking agent is selected from alkaline earth metal or transitionmetal-based oxidizing agents, such as magnesium peroxides, zincperoxides, and calcium peroxides.

In addition, enzymatic breakers may also be used in place of or inaddition to a non-enzymatic breaker. Examples of suitable enzymaticbreakers such as guar specific enzymes, alpha and beta amylases,amyloglucosidase, aligoglucosidase, invertase, maltase, cellulase, andhemi-cellulase are disclosed in U.S. Pat. Nos. 5,806,597 and 5,067,566.

A breaking agent or breaker may be used “as is” or be encapsulated andactivated by a variety of mechanisms including crushing by formationclosure or dissolution by formation fluids. Such techniques aredisclosed, for example, in U.S. Pat. Nos. 4,506,734; 4,741,401;5,110,486; and 3,163,219.

Generally, the temperature and the pH of a fracturing fluid affects therate of hydrolysis of an ester. For downhole operations, the bottom holestatic temperature (“BHST”) cannot be easily controlled or changed. ThepH of a fracturing fluid usually is adjusted to a level to assure properfluid performance during the fracturing treatment. Therefore, the rateof hydrolysis of an ester could not be easily changed by altering BHSTor the pH of a fracturing fluid. However, the rate of hydrolysis may becontrolled by the amount of an ester used in a fracturing fluid. Forhigher temperature applications, the hydrolysis of an ester may beretarded or delayed by dissolving the ester in a hydrocarbon solvent.Moreover, the delay time may be adjusted by selecting esters thatprovide more or less water solubility. For example, for low temperatureapplications, polycarboxylic esters made from low molecular weightalcohols, such as methanol or ethanol, are recommended. The applicationtemperature range for these esters could range from about 120° F. toabout 250° F. (about 49° C. to about 121° C.). On the other hand, forhigher temperature applications or longer injection times, esters madefrom higher molecular weight alcohols should preferably be used. Thehigher molecular weight alcohols include, but are not limited to, C₃-C₆alcohols, e.g., n-propanol, hexanol, and cyclohexanol.

Propping agents or proppants are typically added to the fracturing fluidprior to the addition of a crosslinking agent. However, proppants may beintroduced in any manner which achieves the desired result. Any proppantmay be used in embodiments of the invention. Examples of suitableproppants include, but are not limited to, quartz sand grains, glass andceramic beads, walnut shell fragments, aluminum pellets, nylon pellets,and the like. Proppants are typically used in concentrations betweenabout 1 to 8 lbs. per gallon of a fracturing fluid, although higher orlower concentrations may also be used as desired. The fracturing fluidmay also contain other additives, such as surfactants, corrosioninhibitors, mutual solvents, stabilizers, paraffin inhibitors, tracersto monitor fluid flow back, and so on.

The well treatment fluid composition in accordance with embodiments ofthe invention has many useful applications. For example, it may be usedin hydraulic fracturing, gravel packing operations, water blocking,temporary plugs for purposes of wellbore isolation and/or fluid losscontrol, and other well completion operations. One application of thefluid composition is to use it as a fracturing fluid. Accordingly,embodiments of the invention also provide a method of treating asubterranean formation. The method includes formulating a fracturingfluid comprising an aqueous fluid, a hydratable polymer, a crosslinkingagent, an inorganic breaking agent, and an ester compound; and injectingthe fracturing fluid into a bore hole to contact at least a part of theformation by the fracturing fluid under a sufficient pressure tofracture the formation. Initially, the viscosity of the fracturing fluidshould be maintained above at least 200 cP at 40 sec⁻¹ during injectionand, afterwards, should be reduced to less than 200 cP at 40 sec⁻¹.After the viscosity of the fracturing fluid is lowered to an acceptablelevel, at least a portion of the fracturing fluid is removed from theformation. During the fracturing process, a proppant can be injectedinto the formation simultaneously with the fracturing fluid. Preferably,the fracturing fluid has a pH around or above about 7, more preferablyin the range of about 8 to about 12.

It should be understood that the above-described method is only one wayto carry out embodiments of the invention. The following U.S. patentsdisclose various techniques for conducting hydraulic fracturing whichmay be employed in embodiments of the invention with or withoutmodifications: U.S. Pat. Nos. 6,169,058; 6,135,205; 6,123,394;6,016,871; 5,755,286; 5,722,490; 5,711,396; 5,551,516; 5,497,831;5,488,083; 5,482,116; 5,472,049; 5,411,091; 5,402,846; 5,392,195;5,363,919; 5,228,510; 5,074,359; 5,024,276; 5,005,645; 4,938,286;4,926,940; 4,892,147; 4,869,322; 4,852,650; 4,848,468; 4,846,277;4,830,106; 4,817,717; 4,779,680; 4,479,041; 4,739,834; 4,724,905;4,718,490; 4,714,115; 4,705,113; 4,660,643; 4,657,081; 4,623,021;4,549,608; 4,541,935; 4,378,845; 4,067,389; 4,007,792; 3,965,982; and3,933,205.

The liquid carrier can generally be any liquid carrier suitable for usein oil and gas producing wells. A presently preferred liquid carrier iswater. The liquid carrier can comprise water, can consist essentially ofwater, or can consist of water. Water will typically be a majorcomponent by weight of the fluid. The water can be potable ornon-potable water. The water can be brackish or contain other materialstypical of sources of water found in or near oil fields. For example, itis possible to use fresh water, brine, or even water to which any salt,such as an alkali metal or alkali earth metal salt (NaCO.sub.3, NaCl,KCl, etc.) has been added. The liquid carrier is preferably present inan amount of at least about 80% by weight. Specific examples of theamount of liquid carrier include 80%, 85%, 90%, and 95% by weight.

EXPERIMENTS OF THE INVENTION

In the following microemulsion formulations illustrating differentcompositional aspects of this invention, the coded material are asfollows (a) NIS1 is C₈-C₁₀ ethoxylated alcohol with five (5) moleculesof ethylene oxide (EO) having a low foam generating propensity; (b) NIS2is a copolymer of ethylene oxide and propylene oxide with HLB=15 havinga low foam generating propensity; (c) AIS1 is a C₂-C₁₃ monoalkylbranched propoxy sulfate with four (4) ethylene oxide molecules used toincrease cloud point and decrease freezing point, (d) AIS2 is a sodiumtridecyl ether sulfate used to increase cloud point and decreasefreezing point; (e) H₂O water; (f) IPA is isopropanol or isopropylalcohol (IPA) used as co-solvent and to decrease the freezing point; (g)dLim is D-limonene; (h) 1OA is 1-octanol used as co-solvent anddeformer, and (i) PPG is polypropylene glycol used as de-foamer.

TABLE I List of Composition of This Invention NIS1 % NIS2 % AIS1 % H₂O %dLim % IPA % 1OA % PPG % Sample # (w/w) (w/w) (w/w) (w/w) (w/w) (w/w)(w/w) (w/w)  1 1810-A 8 10.24 0.94 56.66 5.05 11.25 1.88 6.00  2 1910-B8.3 12.46 0.5 54.56 5.05 11.25 1.88 6.00  3 1809B 9 9 3.26 63.76 4.884.88 0.53 4.68  4 1809C 9.82 9.82 1.63 63.76 4088 4.88 0.53 4.68  51110A 9.5 9.5 1.55 59.58 4.72 8 0.77 6.38  6 1110B 9.5 9.5 1.55 57.64.72 10 0.77 6.38  7 1110C 9.4 9.4 1.55 59.9 4.84 7.63 1 6.32  8 1110D9.44 9.44 1.55 59.24 5.17 6.76 1.98 6.36  9 1807B2 10.63 10.63 0 63.764.88 4.88 0.53 4.68 10 1510B 9.78 9.78 1 57.6 4.72 10 0.77 6.38 11 1510C9.72 9.72 1 59.24 5.17 6.76 1.98 6.36 12 3010-E 9.12 9.12 0.15 62.8 5.055.88 1.88 6 13 2410-F 9.16 9.16 0.075 62.7 5.05 6 1.88 6

Referring now to FIG. 1, a port of apparent permeability to nitrogen inmillidarcys versus cumulative fluid injected, before and after treatingwith 1 gal/Mgal of conventional microemulsion system in berea Sandstone@ 140° F. Permeability to air 8-10 millidarcys is shown. Referring nowto FIG. 2, a port of apparent permeability to nitrogen in millidarcysversus cumulative fluid injected, before and after treating with 1gal/Mgal of Sample 9 microemulsion system in berea Sandstone @ 140° F.Permeability to air 8-10 millidarcys is shown. Referring now to FIG. 3,a port of apparent permeability to nitrogen in millidarcys versuscumulative fluid injected, before and after treating with 1 gal/Mgal ofSample 13 microemulsion system in berea Sandstone (200° F. Permeabilityto air 8-10 millidarcys is shown. Referring now to FIG. 4, a port ofapparent permeability to nitrogen in millidarcys versus cumulative fluidinjected, before and after treating with 2 gal/Mgal of Sample 13microemulsion system in berea Sandstone @ 200° F. is shown. Referringnow to FIG. 5, a port of apparent permeability to nitrogen inmillidarcys versus cumulative fluid injected, before and after treatingwith 1 gal/Mgal of Sample 4 microemulsion system in berea Sandstone @200° F. is shown.

It is clear from the above testing data that the post injection data forthe microemulsions system of this invention showed a marked positivechange in apparent permeability compared to convention system, whichactually showed as slight decrease in apparent permeability.

All references cited herein are incorporated by reference. Although theinvention has been disclosed with reference to its preferredembodiments, from reading this description those of skill in the art mayappreciate changes and modification that may be made which do not departfrom the scope and spirit of the invention as described above andclaimed hereafter.

1. A microemulsion system for treating gas wells comprising: asurfactant subsystem including: between about 0.1 weight percent andabout 10 weight percent of monoalkyl branched propoxy sulfate or aplurality of monoalkyl branched propoxy sulfates, between about 0.1weight percent and about 30 weight percent of a low foam generatingethoxylated alcohol comprising a reaction product of an alcohol havingbetween about 8 and about 10 carbon atoms and having an average of about7 ethylene oxide groups per alcohol molecule, and between about 0.1weight percent and about 30 weight percent of a low foam generatingblock copolymer or plurality of block copolymers of ethylene oxide andpropylene oxide having a HLB value between about 7 and 15; a co-solventsubsystem including: between about 0.1 weight percent and about 20weight percent of isopropyl alcohol (IPA), between about 0.1 weightpercent and about 5 weight percent of 1-octanol, and between about 0.1weight percent and about 15 weight percent of a polypropylene glycol;and a solvent subsystem including: between about 2 weight percent andabout 25 weight percent of d-limonene or dipentene, and between about 20weight percent and about 75 weight percent of water, where themicroemulsion system is adapted to treat gas wells.
 2. The system ofclaim 1, wherein the surfactant subsystem further includes at least onealkyl ether sulfate anionic surfactant.
 3. A microemulsion system fortreating gas wells comprising: a surfactant subsystem including: fromabout 0.5 wt. % to about 30 wt. % at least one ethoxylated alcohol, fromabout 0.5 wt. % to about 30 wt. % at least one ethylene oxide(EO)/propylene oxide (PO) copolymer, and from about 0.1 wt. % to about10 wt. % at least one monoalkyl branched propoxy sulfate; a solventsystem including: from about 0.1 wt. % to about 15 wt. % at least oneshort chain linear alcohol, from about 0.5 wt. % to about 10 wt. % atleast one longer chain linear alcohol, and from about 0.5 wt. % to about15 wt. % at least one polypropylene glycol; and a co-solvent systemincluding: from about 0.1 wt. % to about 50 wt. % of at least oneterpene and from about 20 wt. % to about 75 wt. % water, where themicroemulsion system is adapted to treat gas wells.
 4. The compositionof claim 3, wherein the at least one short chain alcohol have betweenabout 1 and about 4 carbon atoms and at least one longer chain linearalcohol have between about 6 and about 10 carbon atoms.
 5. Thecomposition of claim 3, wherein the at least one short chain alcoholhave between about 2 and about 4 carbon atoms and at least one longerchain linear alcohol have between about 7 and about 9 carbon atoms. 6.The composition of claim 3, wherein the at least one short chain alcoholcomprises isopropyl alcohol and the at least one longer chain linearalcohol comprises 1-octanol.
 7. A composition for fracturing asubterranean formation containing gas and penetrated by a wellbore, thecomposition comprising: a fracturing fluid including: a surfactantsubsystem comprising: from about 0.5 wt. % to about 30 wt. % at leastone ethoxylated alcohol, from about 0.5 wt. % to about 30 wt. % at leastone ethylene oxide (EO)/propylene oxide (PO) copolymer, and from about0.1 wt. % to about 10 wt. % at least one monoalkyl branched propoxysulfate; a solvent subsystem comprising: from about 0.1 wt. % to about15 wt. % at least one short chain linear alcohol, from about 0.5 wt. %to about 10 wt. % at least one longer chain linear alcohol, and fromabout 0.5 wt. % to about 15 wt. % at least one polypropylene glycol; anda co-solvent subsystem comprising: from about 0.1 wt. % to about 50 wt.% of at least one terpene and from about 20 wt. % to about 75 wt. %water, where the microemulsion system is adapted to treat gas wells. 8.A composition for drilling into a subterranean formation containing gas,the composition comprising: a drilling fluid including: a surfactantsubsystem comprising: from about 0.5 wt. % to about 30 wt. % at leastone ethoxylated alcohol, from about 0.5 wt. % to about 30 wt. % at leastone ethylene oxide (EO)/propylene oxide (PO) copolymer, and from about0.1 wt. % to about 10 wt. % at least one monoalkyl branched propoxysulfate; a solvent subsystem comprising: from about 0.1 wt. % to about15 wt. % at least one short chain linear alcohol, from about 0.5 wt. %to about 10 wt. % at least one longer chain linear alcohol, and fromabout 0.5 wt. % to about 15 wt. % at least one polypropylene glycol; anda co-solvent subsystem comprising: from about 0.1 wt. % to about 50 wt.% of at least one terpene and from about 20 wt. % to about 75 wt. %water, where the microemulsion system is adapted to treat gas wells. 9.A composition for removing bound water from a producing subterraneanformation containing gas and penetrated by a wellbore, the compositioncomprising: a producing fluid including: a surfactant subsystemcomprising: from about 0.5 wt. % to about 30 wt. % at least oneethoxylated alcohol, from about 0.5 wt. % to about 30 wt. % at least oneethylene oxide (EO)/propylene oxide (PO) copolymer, and from about 0.1wt. % to about 10 wt. % at least one monoalkyl branched propoxy sulfate;a solvent subsystem comprising: from about 0.1 wt. % to about 15 wt. %at least one short chain linear alcohol, from about 0.5 wt. % to about10 wt. % at least one longer chain linear alcohol, and from about 0.5wt. % to about 15 wt. % at least one polypropylene glycol; and aco-solvent subsystem comprising: from about 0.1 wt. % to about 50 wt. %of at least one terpene and from about 20 wt. % to about 75 wt. % water,where the microemulsion system is adapted to treat gas wells.
 10. Acomposition for removing bound water from a producing subterraneanformation containing gas and penetrated by a wellbore, the compositioncomprising: a surfactant subsystem comprising: from about 0.5 wt. % toabout 30 wt. % at least one ethoxylated alcohol, from about 0.5 wt. % toabout 30 wt. % at least one ethylene oxide (EO)/propylene oxide (PO)copolymer, and from about 0.1 wt. % to about 10 wt. % at least onemonoalkyl branched propoxy sulfate; a solvent subsystem comprising: fromabout 0.1 wt. % to about 15 wt. % at least one short chain linearalcohol, from about 0.5 wt. % to about 10 wt. % at least one longerchain linear alcohol, and from about 0.5 wt. % to about 15 wt. % atleast one polypropylene glycol; and a co-solvent subsystem comprising:from about 0.1 wt. % to about 50 wt. % of at least one terpene and fromabout 20 wt. % to about 75 wt. % water, where the microemulsion systemis adapted to treat gas wells.